Forming a subsea wellbore

ABSTRACT

A riserless subsea drilling system includes a tubular drilling string including a drilling bit; a rotating control device including a seal sealed to the drilling string; and a drilling fluid circuit that circulates drilling fluid from a supply line, through an annulus exterior the drilling string and below the rotating control device, through the drilling bit at a downhole end of the drilling string, and through the drilling string toward an uphole end of the drilling string.

TECHNICAL BACKGROUND

This application generally relates to forming a subsea wellbore and,more particularly, to forming a subsea wellbore with a riserlessdrilling system.

BACKGROUND

Typically, in drilling a subsea well, a rig at the water's surface has atubular drilling riser extending from the rig down to a blowoutpreventer stack (BOP) at the sea floor. A drill string extends from therig through the interior of the riser and into the wellbore beingdrilled. Drilling fluid is circulated from the rig, downward through theinterior of the drill string and out of the drill bit at the bottom holeassembly (BHA), and back up through the annulus between the drill stringand the wall of the wellbore and between the drill string and the riser.

SUMMARY

In an example general implementation, a riserless subsea drilling systemincludes a tubular drilling string including a drilling bit; a rotatingcontrol device including a seal sealed to the drilling string; and adrilling fluid circuit that circulates drilling fluid from a supplyline, through an annulus exterior the drilling string and below therotating control device, through the drilling bit at a downhole end ofthe drilling string, and through the drilling string toward an upholeend of the drilling string.

A first aspect combinable with the general implementation furtherincludes a mud motor coupled to the drilling bit and having a centerbypass bore.

A second aspect combinable with any of the previous aspects furtherincludes a flow control device in or upstream of the center bypass bore.

A third aspect combinable with any of the previous aspects furtherincludes a flow control apparatus positioned in the drilling fluidcircuit to control the circulation of drilling fluid.

A fourth aspect combinable with any of the previous aspects furtherincludes a buffer chamber above the drilling bit.

A fifth aspect combinable with any of the previous aspects furtherincludes pressure sensors positioned to measure a pressure differentialacross the seal of the rotating control device.

In a sixth aspect combinable with any of the previous aspects, therotating control device further includes a seawater inlet and a seawateroutlet to circulate a flow of seawater across the seal.

In a seventh aspect combinable with any of the previous aspects, therotating control device further includes an additive to circulate withthe flow seawater across the seal.

In an eighth aspect combinable with any of the previous aspects, theadditive includes detergent.

In a ninth aspect combinable with any of the previous aspects, thesupply line extends from at or near a sea surface, through a subseaenvironment, to the annulus.

In a tenth aspect combinable with any of the previous aspects, thesupply line fluidly connects to the annulus downhole of a blowoutpreventer.

In another example general implementation, a method for forming a subseawellbore includes sealing, with a rotating control device, a portion ofa tubular drilling string against a subsea environment, the tubulardrilling string extending from at or near a subsea surface through thesubsea environment; and circulating, from at or near the sea surface, adrilling fluid in a downhole direction through an annulus between thedrilling string and a wellbore, and then in an uphole direction throughthe drilling string towards the sea surface.

A first aspect combinable with the general implementation furtherincludes circulating the drilling fluid through a supply line, connectedto the annulus downhole of the rotating control device, that extendsthrough the subsea environment to the annulus.

A second aspect combinable with any of the previous aspects furtherincludes determining density and rheological properties of the drillingfluid entering the supply line.

A third aspect combinable with any of the previous aspects furtherincludes determining density and rheological properties of the drillingfluid returned through the drilling string.

A fourth aspect combinable with any of the previous aspects furtherincludes determining, based on the determined densities and rheologicalproperties, a hydrostatic pressure difference between the drilling fluidentering the supply line and the drilling fluid returned through thedrilling string.

A fifth aspect combinable with any of the previous aspects furtherincludes determining, based on the hydrostatic pressure difference, adesired setpoint drilling fluid pressure at a flow control apparatusthrough which the drilling fluid circulates that results in apredetermined drilling pressure at a predetermined downhole location.

A sixth aspect combinable with any of the previous aspects furtherincludes adjusting the flow control apparatus to maintain the desiredsetpoint drilling fluid pressure.

A seventh aspect combinable with any of the previous aspects furtherincludes circulating the drilling fluid through the annulus downhole toa drilling bit at an end of the drilling string, and from the drillingbit into the tubular drilling string.

An eighth aspect combinable with any of the previous aspects furtherincludes circulating the drilling fluid through a reverse circulatingmud motor.

In an example general implementation, a subsea drilling system includesa tubular drilling string that includes a drilling bit at a downhole endof the drilling string, the drilling string configured to extend throughand in contact with a subsea environment; a rotating control devicepositioned on the drilling string above a blowout preventer stack andconfigured to seal a portion of the drilling string against the subseaenvironment; a first drilling fluid pathway including a first conduitthat extends through the subsea environment and an annulus between thedrilling string and a wellbore formed in a subterranean formation; asecond drilling fluid pathway in fluid communication with the firstdrilling fluid pathway through a bottom hole assembly, the seconddrilling fluid pathway including the drilling string; and a circulationsystem configured to circulate a drilling fluid into and through thefirst drilling fluid pathway in a downhole direction and then throughthe second drilling fluid pathway in an uphole direction.

A first aspect combinable with the general implementation furtherincludes a guide sleeve positioned around the drilling string above therotating control device.

In a second aspect combinable with any of the previous aspects, thesecond drilling fluid pathway further includes a second conduit thatextends from at or near the rotating control device through the subseaenvironment.

A third aspect combinable with any of the previous aspects furtherincludes a flow control system configured to control a pressure of thedrilling fluid.

Various implementations of a subsea drilling system according to thepresent disclosure may include one, some, or all of the followingfeatures. For example, the subsea drilling system may allow for fasteroperations as a result of not having to trip the drilling riser before,during and after operations. As another example, the subsea drillingsystem may allow for a smaller footprint rig. As yet another example,the subsea drilling system may allow for less expensive and tangibleassets to be placed in the well. Further, the subsea drilling system mayutilize less intangible expenses compared to conventional deepwaterwells being drilled today. As another example, smaller casing andwellbore sizes may be implemented with the subsea drilling systemaccording to the present disclosure. The subsea drilling system couldrequire substantially lower quantities of drilling and/or completionfluids as well as requiring substantially lower volumes of contingencywell kill fluids and any other fluids that may be required during thewell construction and completion operations. The drilling system couldbe quicker, safer and easier to move off the drilling location in casesof inclement weather, heavy seas, or other occasions requiring thedrilling rig to be moved off and back on to the drilling location, asonly the drill string and not the drilling riser will have to be securedprior to such moves.

The details of one or more implementations are set forth in theaccompanying drawings and the description below. Other features,objects, and advantages will be apparent from the description anddrawings, and from the claims.

DESCRIPTION OF DRAWINGS

FIG. 1 illustrates a schematic diagram of an example implementation of asubsea drilling system;

FIG. 2 illustrates a schematic diagram of a portion of an exampleimplementation of a subsea drilling system that includes a flow controlassembly;

FIG. 3 illustrates a schematic diagram of an example implementation of asubsea drilling system that includes a rotating control device; and

FIG. 4 illustrates an example method for forming a subsea wellbore.

DETAILED DESCRIPTION

The present disclosure describes a riserless, reverse circulationdrilling system and method that includes a rotating control device(RCD), or other sealing device (e.g. an annular preventer or othersimilar device) that prevents (all or substantially all) drilling fluidto escape from the subsea well, but otherwise allowing for drill stringmovement. The system and method enables managed pressure drilling (MPD),e.g., where the pressure of the drilling fluid is controlled relative tothe pressure of the fluids in the subterranean zone being drilled, incertain instances, using mechanisms in addition to the hydrostatic headof the drilling fluid, and in certain instances, to be below, at and/orabove the pressure in the zone.

FIG. 1 shows an example system 100. The system includes a bit 102 anddrilling bottom hole assembly (BHA) 104 at the bottom of a drillingstring 106. The drilling string 106 extends from a drilling vessel 108(e.g., fixed rig, jack-up rig, compliant-tower rig, floating productionsystem, tension-leg platform, spar platform, or otherwise) at thewater's surface 110 into a wellbore 112 being drilled. As shown in thisexample, the system 100 includes a casing 140 installed into a portionof the wellbore 112. The casing 140 can represent, for example, one ormore of a conductor pipe, surface casing, and/or intermediate casing. Insome alternative aspects, the wellbore 112 may be an open holecompletion, e.g., without a casing.

The wellbore 112 extend from a sea floor 115 into one or moresubterranean zones 160 that may include hydrocarbon, or other fluid, ormineral bearing geological formations. As shown in this example, asubsea environment 170 (e.g., saltwater) extends between the watersurface 110 and the sea floor 115. Although described as a subseaenvironment with saltwater, the environment 170 may also include amixture of fresh and saltwater or primarily fresh water.

The tubular drilling string 106 extends through the subsea environment170 from the drilling vessel 108 through the wellbore 112. In thisexample, the system 100 is a riserless drilling system in that thedrilling string 106 is not enclosed within a protective tubular but,instead, is exposed to the saltwater of the subsea environment 170.Alternative implementations of the system 100 may include a riser (e.g.,tubular) that protects the drilling string 106 from the saltwater of thesubsea environment 170.

A blowout preventer (BOP) stack 114 is provided at the top opening ofthe wellbore 112, at the sea floor 115. Generally, the BOP stack 114includes one or more valves (e.g., annular preventers) that can beadjusted to control a flow of formation fluids (e.g., from thesubterranean zone 160). In this example, the BOP stack 114 seals aroundthe casing 140. The BOP stack 114 may include other components such asblind and shear rams (e.g., to cut the drilling string 106 and/or othertubing if necessary), a kill (e.g., to circulate high pressure killfluid to the wellbore 112) and a choke (e.g., to return kill fluid tothe drilling vessel 108). To accommodate such choke and kill lines andother electrical and hydraulic control lines from the surface to the BOPstack 114 (or other components of the system 100), a floating vessel(not shown) may be deployed remote from the drilling vessel 108 toprevent entanglement of the lines/umbilicals with the drilling string106.

A rotating control device (RCD) 116 is provided at the top of the BOPstack 114. The RCD 116 has a sealing element (alternately referred tosimply as the “seal” or “element”) 118 that seals to the drilling string106 and is supported to rotate on bearings relative to an outer housing120 affixed to BOP stack 114. In this example, the seal 118 prevents orsubstantially (e.g., with insignificant fluid loss) prevents a drillingfluid 150 from flowing into the subsea environment 170 during drillingor other operations.

Turning briefly to FIG. 3, a schematic of the RCD 116 is illustrated inmore detail. As shown, the RCD 116 includes pressure sensors 190 aboveand below the seal 118. In some aspects, the pressure sensors 190 maymeasure a pressure differential across the seal 118, e.g., to ensureproper operation/sealing against the drilling string 106. Further, theexample implementation of the RCD 116 includes a fluid inlet 180 and afluid outlet 182 that are adjustably open to the subsea environment 170.For example, seawater may be used for cooling and lubrication of theseal 118. The lubrication can be achieved by pumping small amounts ofseawater from the top of the element 118 when the drilling string 106 isgoing in the hole and from the bottom on the way out of the hole. Insome alternative aspects, the RCD 116 may include a self-lubricationelement 184 and be closed to the subsea environment 170. Further, ifadditional lubrication (e.g., beyond seawater and/or an internallubricant) is required, this may be administered through a subsea HPUfed with a line from surface 110. A suitably environmentally sensitivelubricant (such as a detergent) can be added to the seawater ifnecessary.

The RCD 116 may be active or passive or alternately could be in the formof an annular BOP. The element 118 in the RCD and/or the RCD clampingdevices are controlled from the water's surface 110 either through acontrol line 136 or by use of a remote telemetry technology such as isused with pipe lines and subsea production trees and wellheads. Theelement 118 can be changed out either by using a remote-controlled clampon the RCD 116 or on the element 118 within the RCD 116, and isretrieved with the BHA 104 portion of the drill string 106 on the way tosurface.

The RCD 116, in some aspects, may include a pneumatic apparatus forlatching a bearing assembly or other sub-assembly to the RCD body 120.The latch mechanism may be integral to the RCD body 120 and located inbetween a top and bottom flange connections of the body 120. It mayinclude an annular piston and a latch dog(s) or ring. The annular pistonmay be actuated with a compressible fluid which may be air, nitrogen, orsimilar. The piston has an inner profile such that during actuation, itguides the outer face of the latch ring or dogs radially inward to thelatch position. In some aspects, the piston itself has, along its upperface, collet fingers, which retract under latching pneumatic pressure,but also prevent the piston from falling under its own weight. This inturn, may prevent unintentionally unlatching the RCD body 120 while notin operation, or if pneumatic pressure is lost.

The RCD 116 may also, in some aspects, include a mechanically operatedlatch mechanism that locks into a mating RCD body 120 and forms a sealbetween an inner diameter of the RCD body 120 and an outer diameter ofthe latch mechanism. The latch mechanism can be transported to the RCDbody 120, latched into position, managed for hydraulic locking,unlatched and transported back to the drilling vessel 108 by verticaland rotational manipulations of the drilling string 106 (e.g., solely bythe string 106). In some aspects, the latch mechanism can be transportedon a running tool from the drilling vessel 108 to the RCD body 120 andmechanically actuated through the running tool. The running tool may beintegral to the drilling string 106 and may include collet fingers,J-Slots (e.g., a pin and guide slot used to create relative motionbetween two or more bodies by using the guide slot to direct the motionof the pin or vice versa), or some other device for attaching to thelatch mechanism.

Blind rams and/or an annular preventer of the BOP stack 114 may beclosed during the retrieval of the RCD 116 and/or RCD's sealing element118 until it is replaced. In some implementations, a spacer section maybe provided between the top of the BOP stack 114 and the RCD 116 tofully accommodate the drilling BHA 104 between the blind rams of the BOPstack 114 and the RCD 116.

In some implementations, in order to relieve stress and preventexcessive wear and tear on the RCD 116, its sealing element 118,bearings and also to the BOP 114 and wellhead by the lateral movement ofthe drilling pipe 106 that is unconstrained from the drilling vessel 108floor to the entry point into the RCD 116 and BOP stack 114, a guidesection 172 may be positioned above the RCD 116. Limiting rotation ofthe drill pipe 106, e.g., by including a reverse circulating mud motor,drilling turbine in the drilling BHA 104 to provide the needed RPM tothe drill bit 102, may also help relieve stress and prevent excessivewear and tear on the RCD 116.

The illustrated implementation of the subsea drilling system 100includes a reverse circulation system. For example, the drilling fluid150 is circulated (e.g., from a pumping system 126) from the drillingvessel 108 down a drilling fluid supply line 124 that is coupled to theouter housing 120 of the RCD 116 to flow into the annulus 142 of thewellbore 112 (between the wellbore 112 and the drilling string 106) tothe drill bit 102. The drilling fluid 150 then returns, through thedrill bit 102 and drilling BHA 104, up the center bore of the drillingstring 106 to the drilling vessel 108. As described above, theillustrated implementation of the system 100 is riserless, in that noriser is provided around the drilling string 106 extending from the RCD116 to the drilling vessel 108. In certain instances, the system 100 canuse dual wall drill pipe for the drilling string 106, and the supplyline 124 can then supply drilling fluid 150 to the annular space betweenthe walls of the drilling string 106 and return drilling fluid up thecenter bore.

In some implementations, a bypass line 176 may be fluidly connected tothe drilling string 106 (e.g., within the RCD 116) to provide a flowpath for drilling fluid 150 to the drilling vessel 108. For example, insome implementations, to control or help control backpressure (asdescribed more fully below), drilling fluid 150 returning to thedrilling vessel 108 up through the bore of the drilling string 106 canbe diverted to the bypass line 176 in order to, for instance, bettercontrol fluid pressure in the annulus 142 and/or drilling string 106.

For example, in some implementations, to accommodate well controloperations and/or to use managed pressure drilling (MPD) techniquesduring drilling, controlled backpressure is applied to the drillingfluid 150 in the annulus 142. In example implementations that use areverse circulation of the drilling fluid 150, the mud motor in the BHA104 may be arranged for reverse circulation, which may transmitadditional back pressure on the drilling fluid 150 in the annulus 142when weight on the drilling bit 102 is initially applied (e.g., whenchanging from off-bottom to on-bottom) or as weight on the drilling bit102 is increased, as a turbine or rotor of the mud motor may requiremore force to turn with increasing weight on the drilling bit 102.

To offset the additional back pressure, the differential pressurecreated between on- and off-bottom circulation equivalent circulatingdensity (ECD) is correspondingly reduced. ECD, generally, a formationpore pressure gradient (e.g., of the subterranean zone 160) and afracture pressure gradient (e.g., of the zone 160) may increase with thetrue vertical depth (TVD) of the wellbore 112. A density of the drillingfluid 150 (e.g., a mud weight) may be used that is greater than the porepressure gradient, but less than the fracture pressure gradient, suchthat the drilling fluid 150 pressure lies between the pore pressure andthe fracture pressure. In many cases, the difference between downholepore pressure and fracture pressure is sufficient so that the equivalentcirculating density (ECD) of the drilling fluid remains within theallowable density window. The ECD is the effective density exerted bythe circulating drilling fluid 150 against the formation that takes intoaccount the pressure losses in the annulus 142 above the location in thewellbore 112 being considered (e.g., at the casing shoe or otherwise).In this example reverse circulation technique, ECD comprises the staticmud weight pressure at a depth location in the wellbore 112 added to thepressure losses of the return flow in the drilling string 106 betweenthat depth and the drilling vessel 108 and then converted to densityunits. A typical conversion between ECD and pressure at a downholelocation is:

${{ECD} = {\frac{P_{Loss}}{0.052\mspace{14mu} {TVD}} + \rho_{DF}}},$

Where ECD is in pounds per gallon (ppg), P_(Loss) is annular pressureloss in psi, TVD is true vertical depth in feet, and ρ_(DF) is drillingfluid density (mud weight) in ppg.

Pressure reduction can be implemented with a flow control assembly,which may include one or more apparatus. For example, the flow controlassembly can be or include a relief system, such as a pressure relief orpressure safety valve, placed in one of the return lines to the drillingvessel 108 that is in fluid communication with the annulus 142. Asanother example, the flow control assembly may be or include a nozzleplaced in or immediately in front of the bore in the rotor of the mudmotor. Further, a flow control assembly can be or include a constantflow regulator placed in the bore of a rotor of the mud motor. Further,the flow control assembly can be or include a choke system placed in thebore of the rotor that would allow connectivity to a Human MachineInterface (HMI) that is run in automation with a real time hydrauliccontrol software system.

Regarding the nozzle, regulator, and choke system, and as shown in FIG.2, these can be represented by a flow control device 128 implementedwithin the bore 135 of a mud motor 132 of the BHA 104. The flow controldevice 128, in some aspects, may controllably allow some portion of thedrilling fluid 150 to return through the center bore 135 of the mudmotor 132 and bypass the drive components 134, e.g., the turbine orrotor/stator gap. Thus, the fluid 150 has an alternate path to thedrilling vessel 108 that does not become more difficult to flow throughas weight on the drilling bit 102 increases. The flow control device128, however, has a controlled or reduced flow area, so all of thedrilling fluid 150 does not bypass the drive components 134.

As another example of a flow control assembly, a buffer chamber 130 maybe placed on top of the bit 102 that would allow flow through ports inthe bit 102 for injection, but not allow flow back between the annulus142 and the bit 102. This flow back restriction could simply be arestriction to flow back with nozzles or the back pressure restrictorcould actually have a chamber that would allow the cavity to beenergized with fluid 150 and allow loading as weight on the drilling bit102 increases, and relieving of the energized chamber as weight on bitis reduced.

In certain instances, to run a MPD operation in reverse circulationenvironment, an underbalanced drilling fluid 150 (UB fluid) could becirculated into the wellbore 112. As the UB fluid 150 is beingcirculated, then the flow control device 128 in the mud motor 132 couldbe used to apply controlled back pressure on the wellbore 112 so thatthe well does not experience an underbalanced state. A combination ofthe hydrostatic pressure of the drilling fluid 150, the ECD and the backpressure could allow the wellbore 112 to experience the planned pressureneeded to successfully drill the well.

In some implementations, a continuous circulation system, a rig pumpdiverter, a back pressure pump, and/or trapping pressure could be usedto assist in maintaining constant bottom hole pressure conditions whenmaking a connection or tripping. For instance, with a choke in the rotorof the drilling bit 102, a choking device may still be used at thedrilling vessel 108 to ensure well control in the event that gas thatenters into the system. This can be incorporated into a reversecirculating swivel or downstream in the return flow line 124 back tohandling tanks at the drilling vessel 108.

As another example of a flow control assembly, a plurality of spacedapart one way valves (e.g., flapper valves and/or other type of valve)can be positioned along the length of the drilling string 106 in itscenter bore, oriented to allow flow up the drilling string 106 towardthe drilling vessel 108 and prevent backflow of cuttings-laden fluidsdown the drilling string 106 toward the drill bit 102 when drillingfluid circulation is paused. The arrangement of one way valves mayprevent the majority of cuttings from settling to the bottom of thedrilling string 106, as they may settle no deeper than the nearestvalve. The one-way valves may not need to be pressure tight and can beconfigured to allow some amount of downward fluid and pressurecommunication, for example, by having small bypass passages or holes.

Alternatively or additionally, the drilling string 106 can include aplurality of spaced apart subs having a fluid path through the sub isoff-center from the center bore and having a settling chamber alignedwith the center bore to catch settling cuttings. Monitoring and modelingcan also be used to determine and control the maximum rate ofpenetration (ROP) to not overload the drill pipe 106 with cuttings andcause a blockage of the drill pipe 106.

FIG. 4 illustrates an example method 400 for forming a subsea wellbore,such as, for example, by all or part of the subsea drilling system 100.Method 400 includes step 402, which includes sealing, with an RCD, aportion of a tubular drilling string against a subsea environment. Forexample, in some aspects, the tubular drilling string may be extendedthrough the subsea environment from a drilling platform or other subseadrilling location, and to a wellbore location. The RCD may sealingengage the drilling string, e.g., above a BOP stack, to fluidly decouplea drilling fluid from the subsea environment (e.g., from seawater orother liquid). In some examples, the drilling string may not be enclosedwithin a riser.

Step 404 may include performing a reverse circulation drillingoperation. For example, performing the reverse circulation drillingoperation may include circulating, from the drilling rig, a drillingfluid through one or more circuits (e.g., conduits) that extend from therig through the subsea environment. The drilling fluid is thencirculated into an annulus between the drilling string and a formationwellbore, e.g., at a location below the RCD, below the BOP stack, orbelow both. The drilling fluid is circulated downhole in the annulus andthrough a BHA (e.g., through a reverse circulation mud motor and througha drilling bit). The drilling fluid, and bits of the formation, mayleave the drilling bit and enter a bore of the drilling string. In thebore of the drilling string, the drilling fluid may be circulated upholeto the drilling rig. In some aspects, an uphole directed circuit of thedrilling fluid path may include a bypass circuit, e.g., to manage orhelp manage a drilling fluid pressure in the annulus.

In step 406, a managed pressure drilling operation may be performed. Insome aspects, the managed pressure drilling operation may include one ormore sub-steps. For example, in some aspects, properties of the drillingfluid (e.g., density and/or rheological properties) may be analyzed. Insome instances, the properties may be analyzed (e.g., automatically,without human intervention, or otherwise) as the drilling fluid iscirculated from the drilling rig and as the drilling fluid is returned(e.g., from downhole) to the drilling rig. A difference in a hydrostaticpressure between the drilling fluid circulated from the rig and thedrilling fluid returned to the drilling rig may then be determined(e.g., through a model, algorithmically, or otherwise). Based on thedetermined difference, a desired setpoint drilling fluid pressure may beset to achieve a particular drilling fluid pressure at a downholelocation (e.g., within a particular drilling interval and/or at aparticular subterranean formation).

In some aspects, the managed pressure drilling operation may includefurther sub-steps. For example, in order to maintain the desiredsetpoint of the drilling fluid pressure (e.g., at the drilling rig, alocation downhole, or otherwise), a flow control apparatus may beincluded in the drilling system. In some aspects, the desired setpointdrilling fluid pressure may be maintained at the flow control apparatus.The flow control apparatus may include one or more of a nozzle, choke,valve, or other flow control device placed, e.g., in the drillingstring, in the BHA, and/or in the drilling bit. In some aspects, theflow control apparatus may include a bypass circuit to route drillingfluid from the bore of the drilling string to the drilling rig. Infurther aspects, the flow control apparatus may include a flow controldevice at the drilling rig.

A number of embodiments of the invention have been described.Nevertheless, it will be understood that various modifications may bemade. For example, telemetry communications can be implemented eithervia negative pulse MWD, acoustic systems, siren telemetry systems indrilling operations. Also, sea floor controls might be utilized similarto completion systems and Christmas trees. Accordingly, otherembodiments are within the scope of the following claims.

What is claimed is:
 1. A riserless subsea drilling system, comprising: atubular drilling string comprising a drilling bit; a rotating controldevice comprising a seal sealed to the drilling string; and a drillingfluid circuit that circulates drilling fluid from a supply line, throughan annulus exterior the drilling string and below the rotating controldevice, through the drilling bit at a downhole end of the drillingstring, and through the drilling string toward an uphole end of thedrilling string.
 2. The riserless subsea drilling system of claim 1,further comprising: a mud motor coupled to the drilling bit and having acenter bypass bore; and a flow control device in or upstream of thecenter bypass bore.
 3. The riserless subsea drilling system of claim 1,further comprising a flow control apparatus positioned in the drillingfluid circuit to control the circulation of drilling fluid.
 4. Theriserless subsea drilling system of claim 1, further comprising a bufferchamber above the drilling bit.
 5. The riserless subsea drilling systemof claim 1, further comprising pressure sensors positioned to measure apressure differential across the seal of the rotating control device. 6.The riserless subsea drilling system of claim 1, wherein the rotatingcontrol device further comprises a seawater inlet and a seawater outletto circulate a flow of seawater across the seal.
 7. The riserless subseadrilling system of claim 6, wherein the rotating control device furthercomprises an additive to circulate with the flow seawater across theseal.
 8. The riserless subsea drilling system of claim 7, wherein theadditive comprises detergent.
 9. The riserless subsea drilling system ofclaim 1, wherein the supply line extends from at or near a sea surface,through a subsea environment, to the annulus.
 10. The riserless subseadrilling system of claim 9, wherein the supply line fluidly connects tothe annulus downhole of a blowout preventer.
 11. A method for forming asubsea wellbore, comprising: sealing, with a rotating control device, aportion of a tubular drilling string against a subsea environment, thetubular drilling string extending from at or near a subsea surfacethrough the subsea environment; and circulating, from at or near the seasurface, a drilling fluid in a downhole direction through an annulusbetween the drilling string and a wellbore, and then in an upholedirection through the drilling string towards the sea surface.
 12. Themethod of claim 11, further comprising circulating the drilling fluidthrough a supply line, connected to the annulus downhole of the rotatingcontrol device, that extends through the subsea environment to theannulus.
 13. The method of claim 12, further comprising: determiningdensity and rheological properties of the drilling fluid entering thesupply line; determining density and rheological properties of thedrilling fluid returned through the drilling string; determining, basedon the determined densities and rheological properties, a hydrostaticpressure difference between the drilling fluid entering the supply lineand the drilling fluid returned through the drilling string; anddetermining, based on the hydrostatic pressure difference, a desiredsetpoint drilling fluid pressure at a flow control apparatus throughwhich the drilling fluid circulates that results in a predetermineddrilling pressure at a predetermined downhole location.
 14. The methodof claim 13, further comprising adjusting the flow control apparatus tomaintain the desired setpoint drilling fluid pressure.
 15. The method ofclaim 11, further comprising circulating the drilling fluid through theannulus downhole to a drilling bit at an end of the drilling string, andfrom the drilling bit into the tubular drilling string.
 16. The methodof claim 15, further comprising circulating the drilling fluid through areverse circulating mud motor.
 17. A subsea drilling system, comprising:a tubular drilling string that comprises a drilling bit at a downholeend of the drilling string, the drilling string configured to extendthrough and in contact with a subsea environment; a rotating controldevice positioned on the drilling string above a blowout preventer stackand configured to seal a portion of the drilling string against thesubsea environment; a first drilling fluid pathway comprising a firstconduit that extends through the subsea environment and an annulusbetween the drilling string and a wellbore formed in a subterraneanformation; a second drilling fluid pathway in fluid communication withthe first drilling fluid pathway through a bottom hole assembly, thesecond drilling fluid pathway comprising the drilling string; and acirculation system configured to circulate a drilling fluid into andthrough the first drilling fluid pathway in a downhole direction andthen through the second drilling fluid pathway in an uphole direction.18. The subsea drilling system of claim 17, further comprising a guidesleeve positioned around the drilling string above the rotating controldevice.
 19. The subsea drilling system of claim 17, wherein the seconddrilling fluid pathway further comprises a second conduit that extendsfrom at or near the rotating control device through the subseaenvironment.
 20. The subsea drilling system of claim 17, furthercomprising a flow control system configured to control a pressure of thedrilling fluid.